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  1. DEP Regulatory RequirementsChapter 78 Subchapter D Dave English Division of Compliance and Data Management Bureau of Oil and Gas Management

  2. Focus • Significant changes to Subchapter D. • Relevant revisions to Subchapters A, C, and E

  3. Oil and Gas Wells and the Middle Devonian Marcellus Formation

  4. Chapter 78 Subchapter D addresses: • New well drilling, casing, cementing, completion and operational practices

  5. Chapter 78 Subchapter D addresses: • Currently operating oil and gas wells

  6. Chapter 78 Subchapter D addresses: • Plugging abandoned wells

  7. Rationale for Proposed Rulemaking: Needs Assessment • New drilling and completion practices used to develop Marcellus and other “unconventional” formations • Stray gas migration incidents (Marcellus and shallow oil and gas wells) • Well control incidents (e.g. EOG incident June 3, 2010 in Clearfield County) • Hydraulic fracturing additive disclosure • Mandatory production reporting – Act 15

  8. Final Rulemaking 25 Pa. Code Chapter 78Background • Initial draft presented to TAB September 17, 2009 • DEP met with TAB and subcommittee four additional times (10/28/09, 1/14/10, 1/21/10, 3/25/10) • Advanced Notice of Proposed Rulemaking: Public comment period January 30, 2010 – March 2, 2010 • Notice of Final Rulemaking: Public comment period July 10, 2010 – August 9, 2010 • Approval by EQB, IRRC, Attorney General’s Office. • Final Regulations approved on publication in the Pennsylvania Bulletin February 5, 2011

  9. Final Rulemaking 25 Pa. Code Chapter 78:Significant Revisions Well Control Well Construction (casing and cementing operations) Mechanical Integrity of Existing Wells Gas Migration Response Well Reporting

  10. Future Rulemaking: Next Regulatory Package • Revisions to Plugging regulations: 78.91-78.98 • Revisions to Subchapter C: Environmental Protection Performance Standards • Other revisions and modifications, i.e., “tweaks” to Subchapter D

  11. Chapter 78. Oil and Gas Wells Subchapter A: General Provisions

  12. Chapter 78. Oil and Gas Wells Subchapter A: General Provisions – new definitions added Conductor pipe Intermediate casing L.E.L. (lower explosive limit) Unconventional formations

  13. Chapter 78. Oil and Gas Wells Subchapter C: Environmental Protection Performance Standards

  14. 78.55. Control and Disposal Plan Plan must include operator’s pressure barrier policy that identifies barriers to be used during specific operations Plan must be available at the well site for review during drilling and completion activities List of emergency contact phone numbers for the area in which the site is located must be prominently displayed at the well site during drilling, completion, and workover activities

  15. Chapter 78. Oil and Gas Wells • Subchapter D: Well Drilling, Operation and Plugging

  16. 78.72 Use of Safety Devices – BOP Equipment(New language in italics) BOP equipment to be used: When drilling well intended to produce natural gas from an unconventional formation When drilling out frac plugs Where pressures are anticipated at the well site that may result in a loss of well control Where operator is drilling in an area where there is no prior knowledge of pressure or natural open flow When drilling conservation wells When drilling within 200 feet of a building

  17. 78.72 Use of Safety Devices – BOP Equipment • Controls for the blow-out preventer must be accessible to allow actuation of the equipment • Additional controls for the BOP with a pressure rating of 3000 psi, not associated with the rig hydraulic system, must be located at least 50 ft. away from the drilling rig such that the BOP can be activated if control of the well is lost

  18. 78.72 Use of Safety Devices – BOP Equipment • Remote Accumulator for BOP Actuation • Close-up of BOP Controls

  19. 78.72 (d) BOP Equipment Testing • Annular-type: must test according to the manufacturer’s instructions, or by a professional engineer, before placing in service • Equipment failing test must not be used until it is repaired/replaced and passes the test

  20. 78.72(d) BOP Equipment Testing • Ram-type: must test for both pressure and ram operation before placing in service on the well • Testing in accordance with API RP53 • If not in good working order, drilling must cease until BOP equipment is repaired/replaced and re-tested

  21. 78.72 BOP: Additional requirements • All lines, valves and fittings between the closing unit and the BOP stack must be flame resistant and have a rated working pressure that meets or exceeds the requirements of the BOP system • When BOP is installed or required, an individual must be present at the well site with a current certification from a well control course accredited by the International Association of Drilling Contractors or other organization approved by DEP • Pressure barriers identified in drilling and completions operations requiring two mechanical barriers must be capable of being tested. This does not mean that all operations utilizing BOP equipment must employ two mechanical barriers • A stripper barrier or stripper heads are not considered adequate barriers • A coiled tubing rig or hydraulic workover unit with appropriate BOP equipment must be utilized during post-completion cleanout operations in unconventional formations penetrated by a horizontal wellbore • DEP will be developing pressure barrier policy

  22. Chapter 78 Major Changes to Well Construction and Cementing and Other Changes to Subchapter D • Revised casing standards • New requirement for casing and cementing plan • New Section on lost circulation • Revised cement standards • New Section on mechanical integrity of existing wells

  23. 78.73 General Provisions: Revised language • Operator must construct well in accordance with this Chapter and ensure that the integrity of the well is maintained and health, safety, environment and property are protected • Operator must prevent gas, oil, brine, completion and servicing fluids, and any other fluids or materials from below the casing seat from entering fresh groundwater, and shall otherwise prevent pollution or diminution of fresh groundwater • Reduced pressure at surface or coal protective casing seat may not exceed 80% of the hydrostatic pressure of the surrounding fresh groundwater (0.8 X 0.433) X casing length (ft)

  24. 78.73 General Provisions: New Language • Excess gas encountered during drilling, completion or stimulation must be flared, captured or diverted from the drilling rig in a manner that does not create a hazard to public health or safety • Wells must be equipped with a check valve to prevent backflow from pipelines into well (except gas storage wells)

  25. 78.75a. New Section: Area of Alternative Methods • DEP may designate an area of alternative methods if it determines that well drilling and operating requirements beyond those provided in this Chapter are necessary • Notice of proposed area of alternative methods will be published in PA Bulletin • Wells drilled within this area must meet the requirements specified by the Department unless the operator obtains DEP approval to drill, operate or plug the well in a different manner that is at least as safe and protective of the environment as the requirements in the area of alternative methods

  26. 78.76. Drilling within a Gas Storage Reservoir • An operator proposing to drill in a gas storage area (or the surrounding reservoir protective area….normally 2000 ft) must send a copy of the location plat, the drilling/casing/cementing plan, and the anticipated date drilling will commence to the gas storage reservoir operator • New language requires that information above also be sent to the Department along with proof of notification to the gas storage reservoir operator; DEP must approve the proposal prior to drilling

  27. 78.81-78.87. Casing and Cementing

  28. 78.81 General Provisions • Casing and cementing must: • Allow effective control of the well at all times • Prevent the migration of gas and other fluids into fresh groundwater • Prevent the pollution or diminution of fresh groundwater • Prevent the migration of gas or other fluids into coal seams

  29. 78.82. Use of Conductor Pipe • New rulemaking additions: • Conductor pipe shall be installed in a manner that prevents the subsurface infiltration of surface water or fluids • Conductor pipe shall be made of steel

  30. 78.83. Surface and Coal Protective Casing and Cementing Procedures: New Language • Wells drilled, altered, reconditioned or recompleted after final regulations may not utilize surface casing, or any casing functioning as water protection casing, unless: • The well is an oil well where the operator does not produce any gas generated by the well and the annulus between the surface casing and the production pipe is left open • The operator demonstrates that the pressure in the wellbore at the casing seat is no greater than the pressure allowed by (new) 78.73(c): (0.8 X 0.433 psi/ft X casing length (ft). Operator must install a working pressure gauge that can be inspected by the Department • Determination may be with a pressure test to 80% of the calculated hydrostatic pressure at the surface casing seat

  31. 78.83. Surface and Coal Protective Casing and Cementing Procedures: New Language Surface casing may not be set more than 200 feet below the deepest fresh groundwater except as necessary to set the casing in consolidated rock Surface casing hole must be drilled using air, freshwater, or freshwater-based drilling fluid Wellbore must be conditioned to ensure an adequate cement bond between the casing and formation prior to cementing Centralizers: at least one within 50 ft. of the surface casing seat, then in intervals no greater than every 150 ft. above the first centralizer

  32. 78.83. Surface and Coal Protective Casing and Cementing Procedures: New Language • Operator must document the depth of the fresh groundwater zone in the well and record if additional fresh groundwater is encountered below the surface casing • Coal protective string must have at least two centralizers, one within 50 ft. of the casing seat and the second within 100 ft. of the surface • When cementing in lost circulation zones, using a pour string/tremie pipe to cement above the cement basket does not constitute “permanently cementing” the surface or coal protective casing pursuant to new Section 78.78b (relating to Casing and Cementing – Lost Circulation)

  33. 78.83a. Casing and Cementing Plan: New Section • Operator must prepare a casing and cementing plan showing how the well will be drilled and completed • Plan must include: • Anticipated depth and thickness of any producing formation, expected pressures and anticipated fresh groundwater zones, and the method or information by which the depth of the deepest fresh groundwater was determined (discussed later) • Diameter of the borehole • Casing type, depth, diameter, wall thickness, and burst pressure rating • Cement type, additives, and estimated amount • Estimated location of centralizers • Proposed borehole conditioning procedures • Alternative methods or materials as required by DEP as a condition of the well permit • Plan must be available at the well site for review, may be required by the Department for review and approval (for permit issuance), and any revisions to the plan made as a result of on-site modifications must be documented by the operator, initialed and dated, and available for DEP review

  34. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Regulatory definition of “deepest fresh groundwater” “The deepest fresh groundwater bearing formation penetrated by the wellbore as determined from drillers logs from the well or from other wells in the area surrounding the well or from historical records of the normal surface casing seat depths in the area surrounding the well, whichever is deeper. “ Buckwalter & Moore (2006)

  35. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Standard groundwater quality classification schemes Fetter (1994) Fresh 0 to 1,000 mg/l TDS Brackish 1,000 to 10,000 mg/l TDS Saline 10,000 to 100,000 mg/l TDS Brine >100,000 mg/l TDS Quiñones-Aponte & Wexler (1995) Fresh <1,000 mg/l TDS Slightly Saline (brackish) 1,000 to 3,000 mg/l TDS Moderately Saline (brackish) 3,000 to 10,000 mg/l TDS Very Saline (saltwater) 10,000 to 35,000 mg/l TDS Brine >35,000 mg/l TDS Olsthoorn (2008)

  36. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Some numerical considerations in Pennsylvania Delaware River Basin Commission (DRBC) Freshwater is “water containing less than 1,000 mg/l of dissolved solids, most often salt.” 40 CFR 144.3 – United States EPA “Underground source of drinking water (USDW) means an aquifer or its portion: (a)(1) Which supplies any public water system; or (2) Which contains a sufficient quantity of ground water to supply a public water system; and (i) Currently supplies drinking water for human consumption; or (ii) Contains fewer than 10,000 mg/l total dissolved solids; and (b) Which is not an exempted aquifer.” “10,000 mg/l is FAR TOO SALINE for drinking water supplies in this Commonwealth”

  37. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Numerical considerations elsewhere Texas: 3000 mg/l TDS Oklahoma: 10,000 mg/l TDS Illinois: 10,000 mg/l TDS New York: 1,000 mg/l TDS Alberta: 4,000 mg/l TDS to a depth not to exceed 600 meters

  38. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Numerical considerations (31 states surveyed) GWPC (2009)

  39. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Numerical considerations (15 states with quantitative definition) GWPC (2009)

  40. Section 78.83a.(a)(1): Methodology for Determining Deepest Fresh Groundwater Techniques for defining base of deepest fresh groundwater aquifer Estimating fracture zone yield and measuring specific conductance using a calibrated meter during drilling Standard water well geophysical logging of tophole – specific conductance critical, but other logs may help corroborate water-bearing zones More sophisticated geophysical logging of tophole per EPA UIC recommendations (SP log or resistivity/porosity log) Installation of monitoring wells at well pad and groundwater testing Information from offset wells including water well testing, geophysical log data, and surface casing set depths;considering water well offsets alone will typically not be enough Williams (2010)

  41. 78.83b. Casing and Cementing – Lost Circulation: New Section • If cement used to permanently cement the surface or coal protective casing cannot be circulated to the surface due to lost circulation, the operator shall determine the top of cement, notify the Department and meet one of the following: • Run additional string 50 deeper than where circulation was lost, cement back to lost circulation string casing seat, vent the annulus, meet pressure requirements of 78.73(c) • Run production casing and set on packer, vent the annulus • Run production casing to formation being produced, cement to surface • Run intermediate and production casing and cement both strings to surface • May also emplace supplemental cement in addition to the above

  42. 78.83b. Casing and Cementing – Lost Circulation: New Section- continued Policy: cement returns to surface followed by cement drop may be considered to be permanently cementedifthe DEP inspector determines an adequate amount of surface casing cement was placed above the seat. Top of cement determination must be made and notification given to the DEP inspector for evaluation of casing cement adequacy and subsequent approval for remedial casing options. Must be done prior to continuation of drilling (e.g. no TOC determination after well drilled/completed to TD). In addition to remedial casing options, the minimum amount of surface casing cement above seat and corresponding maximum amount of uncemented surface casing will be made on a case-by-case basis by DEP. In certain cases, the well may need to be plugged and abandoned if only a minimal amount of cement exists above the surface casing seat (a “catastrophic” loss of cement). DEP may require remedial cementing from surface and/or pressure-testing of the casing string to determine integrity of the well and ensure protection of the surface casing seat.

  43. 78.83c. Intermediate and Production Casing: New Section • Prior to cementing intermediate and production casing, the borehole, mud, and cement must be conditioned to ensure an adequate cement bond between the casing and the formation • If a well is to be equipped with intermediate casing, centralizers must be used and the casing must be cemented to the surface by the displacement method; gas may be produced off the intermediate casing if a shoe test demonstrates that all gas will be contained within the well and a relief valve is installed at the surface that is set at less than the shoe test pressure (this pressure must be recorded in the completion report) • Except as provided by 78.83, each well must be equipped with production casing; centralizers must be used; the production string may be set on a packer or cemented in place; annular space must be cemented to a point at least 500 ft. above the TVD or at least 200 ft. above the uppermost perforations, whichever is greater.

  44. 78.84. Casing Standards: Original Language • Casing must withstand the effects of tension, and prevent burst and collapse during its installation, cementing, and subsequent drilling and producing operations • Casing must be equipped with appropriate equipment to center the casing through the hole in fresh groundwater zones • Coal protective casing must have a minimum wall thickness of 0.23 inches

  45. 78.84. Casing Standards: New Language • All casing must be a string of new pipe with a pressure rating at least 20% greater than the anticipated maximum pressure • Used casing may be approved but must be pressure tested after cementing and before continuation of drilling; a passing pressure test is holding the maximum anticipated pressure for 30 minutes with no more than a 10% change in pressure. Pressure testing should be done before significant gel strength has developed in the cement. API RP65 Part 2 • New or used plain end casing that is welded must be pressure tested and hold the maximum anticipated pressure for 30 minutes with no more than a 10% change in pressure • Welded casing must be welded using at least three passes with the joint cleaned between each pass • Welder must be trained and certified in the applicable API, ASME, AWS or equivalent standard for welding casing and pipe or an equivalent training and certification program; a person with 10 or more years of experience welding casing does not need to be certified Note that the certification requirements do not kick in until August 5, 2011

  46. 78.85. Cement Standards: Original Requirements • Cement must resist degradation by chemical and physical conditions in the well • Minimum compressive strength of 350 psi in accordance with API spec 10; cement must set for a minimum period of eight (8) hours prior to the resumption of actual drilling • Operator may request approval from DEP to reduce the cement setting time when special cement or additives are used

  47. Chapter 78.85: New Cement Standards Revised cement standards: Cement must protect casing from corrosion and geochemical, lithologic and physical conditions of the surrounding wellbore Gas-block additives and low fluid-loss slurries in areas of known shallow gas-producing zones are required Zone of critical cement around surface casing seat True eight-hour WOC (wait on cement) before casing may be disturbed One-day notification to DEP prior to cementing of surface casing Cement job log must be prepared and available at the well site during drilling operations and maintained for at least five years

  48. Chapter 78.85: New Cement Standards Zone of Critical Cement: Applies to bottom 300 ft. of surface casing cement, or entire cemented string if the surface casing string is less than 300 ft Cement must achieve a 72-hour compressive strength of 1200 psi Cement must achieve a free-water separation of no more than 6 milliliters of water per 250 milliliters of cement

  49. Chapter 78.85: New Cement Standards Eight-hour WOC (wait on cement) – casing may be not be disturbedby: Releasing pressure on the cement head; if check valves on float shoe are secure, the pressure may be released at a continuous, gradual rate after four hours Nippling up on or in conjunction to the casing Slacking off by the rig supporting the casing in the cement sheath Running drill pipe or other mechanical devices into or out of the wellbore with the exception of a wireline used to determine the top of cement

  50. Chapter 78.85: New Cement Standards Cement job log – required components: Mix water temperature and pH Type of cement with listing and quantity of additives Volume, yield, and density in ppg of the cement Amount of cement returned to the surface Cementing procedural information including a description of the pumping rates in bbl/min, pressure in psi, time in min, and the sequence of events during the cementing operations Logs must be available for all cement jobs done after 2/5/2011.